The present invention relates to a method for determining whether changes in subsurface formations, such as fractures, produced within the earth have crossed a given boundary. In particular, the method provides near real time assessment of fracture propagation that can be used to guide a hydraulic fracturing procedure.
Hydraulic fracturing (also known as hydrofracturing or fracking) is a technique used to increase hydrocarbon production in tight, low-permeability formations. A high-pressure fluid creates fractures in a subsurface rock, often a shale, which allows hydrocarbons to flow to a well bore. Fracking has enabled commercial production from unconventional formations. However, fracking is more expensive than the conventional methods used to produce gas and oil, and fracked wells exhibit a much faster decline in production than conventional wells. Furthermore, there are environmental concerns due to the amount of water that is needed and the possibility of fracture fluid propagating into undesired locations.
A paradigm for hydraulic fracture is shear failure on preexisting fractures and faults in the shale. This shear creates a network of relatively permeable flow paths and thus enhances productivity from the extremely-low-permeability formations. Microseismic events recorded during hydraulic fracturing are evidence of this shear, and the “clouds” of microseismic events associated with multiple hydraulic fracturing stages in a well are generally assumed to define the stimulated rock volume (SRV) from which the gas is being produced. However, in studies of both single and multiple wells, it has been shown that the number of microseismic events does not correlate with production. A simple mass balance calculation illustrates that the cumulative deformation associated with the microseismic events can account for only a small fraction of the production.
The particular defect in existing seismic methods for monitoring hydrofractures is that the underlying seismic data represent the fracture of the host rock rather than the passage of fluid into the new pore spaces and the resulting increase in porosity. As a result, seismic methods are not generally considered adequate for setting the parameters for hydrofracturing a given rock or shale. Furthermore, present seismic data processing takes many hours to complete, and even if the methods were deemed adequate, present seismic survey information cannot be used to guide and control a hydrofracturing operation in the field.
A particular need is to be able to monitor, during the course of a hydrofracturing procedure, whether fractures have propagated into a specific region. For example, it is of significant economic importance that the fractures reach fully into the space between well bores so that a potential hydrocarbon resource can be fully accessed. Conversely, it is also important to know if fractures have propagated out of a desired region, for example into a region that has already been fractured by an earlier hydrofracturing procedure (e.g., from an adjacent well), into a region leased or owned by another organization or above a certain vertical boundary where the fracturing is desired or allowed.
Electromagnetic (EM) methods can produce three-dimensional (3D) images of fluid distribution within the earth by mapping variations in electrical resistivity. Cross-well EM has been used throughout the world to image resistivity changes due to water and steam injection in deep (>5,000 ft) hydrocarbon reservoirs. The more recent method of borehole-to-surface EM (BSEM) can produce accurate images of fluid distribution up to 2 km from a well. However, the EM signal produced by hydrofracturing is limited by the small opening of the fractures and by the depth of present commercial tight formations, which can generally be 6,000 to 12,000 feet deep.
An advance in EM methods specifically for the deep subsurface is described in International Patent Application No. PCT/US2012/39010, entitled “System and Method to Measure or Generate an Electrical Field Downhole”, by Hibbs and Glezer, which is incorporated herein by reference. As illustrated in FIG. 1, a subsurface electric current is forced to flow laterally through the ground (i.e., orthogonal to a vertical borehole) at a distance at least equal to the radial distance between the source and a number of counter electrodes located at a distance from the well on the order of the depth of the source electrode. This configuration increases the current flowing in the ground at formation depth and at a large lateral offset from the borehole. A further advancement described in International Patent Application No. PCT/US2013/058158, entitled “System and Method to Induce an Electromagnetic Field within the Earth”, by Hibbs and Morrison, which is also hereby incorporated by reference, is to remove the source electrode at depth within the casing and instead drive the entire casing of the borehole at the desired voltage, V, by making an electrical connection at or near the top of the casing. For convenience, these EM source configurations, comprised of a conducting well casing and a suite of surface counter electrodes, are termed a Depth to Surface EM (DSEM) source.
Calculations have shown that the combination of a DSEM source with advanced EM sensors at the surface has the capability to detect the EM signal change produced by hydrofracturing a typical shale. In addition, it is possible that, by using fluid modified to have an enhanced EM signature, methods such as cross-well EM and BSEM will similarly be able to detect a hydrofracture signal.
However, calculating the field change due to a change in the distribution of electrical resistivity in the earth requires substantial computation. Moreover, there is no unique transformation connecting a given distribution of measured EM fields at the earth's surface to a specific distribution of subsurface resistivity. In practice, the best that can be done is to calculate iteratively the subsurface resistivity distribution that best matches the expected geology and measured surface field distribution. This lack of a unique inverse solution considerably increases the computational time and resources needed to interpret EM data. As a result, it is not feasible to process an EM signal change associated with a hydrofracturing operation in a time compatible with providing information to guide the hydrofracturing process.
Accordingly, there is a need to develop a practical method to conduct an EM survey and process the EM data in a short enough time that it can be used to decide whether to modify or cease an active hydrofracturing operation.